先鋒自然資源 (PXD) 2003 Q2 法說會逐字稿

At this time I would like to welcome everyone to the Evergreen Resources second-quarter 2003 operating and financial results conference call, hosted by Mark Sexton, President and CEO; Kevin Collins, Executive Vice President and CFO; and John Kelso, Director of Investor Relations. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question and answer period. (CALLER INSTRUCTIONS). I would now like to turn the conference over to John Kelso.

Thanks to everyone for joining us today for our second-quarter conference call. We appreciate your interest. I would like to start off by mentioning that this call is being broadcast live over the Internet with an accompanying slideshow. To view the webcast, go to our web page, at evergreengas.com. I would also like to mention that we have a new website that will be activated this Monday.

Over the next half-hour or so, management will discuss today's press release, which provided operational and financial results for the second quarter of 2003, as well as estimates for the remainder of 2003. These forward-looking statements are made under the safe harbor provisions established by the SEC. The risks and uncertainties involved in these forward-looking statements are described in more detail in the Company's most recent annual report on form 10-K, which, of course, is filed with the SEC.

A couple of other brief announcements. Evergreen will be presenting at the Colorado Oil and Gas Association's Rocky Mountain Natural Gas Strategy and Investment Forum Conference in Denver this Tuesday, which is August 5. Mark Sexton's presentation is scheduled for 1:15 Denver time, and that is going to be held at the Colorado Convention Center. We certainly hope you can make it.

With that, I would like to turn it over to turn it over to the Chief Financial, Kevin Collins.

Thank you all very much for joining us this morning. Yesterday, our Board approved a two-for-one stock split for shareholders of record on August 29, 2003, as a result of our strong stock price performance, our strong financial condition and operating results. We anticipate this should make the stock more accessible to additional investors.

Evergreen reported record net income of 18.4 million, or 92 cents per diluted share, as noted on slides 3-4. We have also included our quarterly net income and diluted earnings per on slides 5 and 6. Our production guidance for the quarter was 11.0-11.3. Our actual production was 11.174, as noted on slide 7, or 123 MMcf per day, as noted on slide 8. Our average daily production has increased for 33 consecutive quarters.

Production for July is expected to be 3.86 Bcf. Our current production is 127 MMcf per day. The (indiscernible) for production for the third quarter is estimated to be 128-129 MMcf per day. On slides 9 and 10, our production estimates for the third quarter will be 11.6-11.8. We have tweaked the higher end of our guidance in the third quarter and adjusted it to 11.8 from 11.9, and we have made no changes to the fourth-quarter production guidance of 11.8-12.1. Our guidance, then, for 2003, will be 45.1 Bcf, and at the upper end, 45.6 Bcf for 2003 for the Raton Basin production.

Last quarter, we gave out guidance for 2004 of 70-72 Bcf. We have had no changes to that, except for the potential adjustment to the Carbon asset, as which we will discuss during the conference call. We have excluded the Carbon production from our guidance because of the potential sale of the Carbon US assets. To update everybody on the Carbon transaction, our current estimate of closing on the transaction is approximately on or before September 30.

Evergreen may be in a position to sell the US assets. Whether or not we sell those assets, we're still in a great position to (indiscernible) the development of the US assets of Carbon Energy. If a sale dose take place, this would effectively complete the private placement to us and would reduce debt and interest expense going forward. Evergreen was approached by another entity to acquire the US assets, and the timing of this transaction has not been determined at this point.

Assuming the closing date of September 30, our production estimates for the fourth-quarter for Carbon Energy would be -- assuming we have the US assets -- would be 0.7-0.8 Bcf, or 7.6-8.7 MMcf per day for the fourth-quarter, and for the Canadian assets would be 1.1-1.2 Bcf, or 11.9-13 MMcf per day for the fourth-quarter. The total reserves for Carbon Energy as of our acquisition date of March 31 was approximately 56.6 Bcf for the US assets and 31.1 Bcf for the Canadian assets.

The drilling program for 2003 for the Raton Basin is 160 wells. As of today, July 31, the total wells drilled to date is 113, and we have 43 wells in various stages of completion. If you turn to slide 15, we have noted what our hedging position is for the remainder of 2003. We have had no changes from our previous guidance, in terms of our hedge position. For the third quarter, we estimate that the -- we would be 72 percent hedged at a net price to Evergreen of $4.37 per Mcf. And for the fourth-quarter, we would be 69 percent hedged at a net price of $4.37.

LOE -- as noted on slide 16, LOE costs increased in the second quarter. We noted the reasons for that in our press release. Our guidance for the third and fourth quarters has been increased, as noted on slide 17 -- our second half cost estimates. The LOE has been increased to 50-52 cents for the third quarter and 45-47 cents for the fourth-quarter, respectively.

G&A, we have increased for a number of reasons, but it is primarily due to the additional personnel and related costs, and is somewhat due to gearing up for the Sarbanes-Oxley act and the requirements associated with that act -- and also for gearing up for our new development programs later this year and also next year. We anticipate that these costs will continue through 2003, and have increased our guidance for the third and fourth quarters to 27-29 cents and 26-28 cents, respectively.

DD&A for the third and fourth-quarter has been adjusted from our previous guidance to eliminate the effects of the Carbon Energy transaction. The item shown in the guidance is just related to Evergreen Resources only. However, depending on the outcome and timing of the potential sale of the Carbon US assets, we have decided not to provide any guidance on DD&A for third quarter and possibly the fourth-quarter. Interest expense is in line with previous guidance. Debt was 230 million at 6/30/03. Our current debt level is 223 million as of today.

Capital expenditures are noted on slide 18. CapEx for the second quarter was approximately 49.5 million, slightly lower than our 56.2 estimate; however, this is actually due to the timing of expenditures. We don't expect any change to the CapEx of 275 million as of today.

We recently completed a midyear reserve estimate of the Raton Basin only. These reserves were audited by Netherland Sewell & Associates. Our reserves at 6/30 were approximately 1.305 Tcf, which is up 5 percent from the year end numbers of 1.239 Tcf. We added approximately 87.7 Bcf of gas reserves, less production of 21.7, for a net increase of 66 Bcf. There were no revisions to the previous estimates. Our PD value at a spot price of 4.71 on 6/30 with approximately $2 billion.

Our reserves for the first six months were in line with internal expectations. We had performed our drilling program to concentrate on increasing production. We had drilled 40 infill wells in the first six months and converted 68 PDODs (ph) to PDPs, which did not set up a number of new locations. Our average reserves were in line with our expectation and along with our average costs. The drilling for the remainder of 2003 will be, again, to enhance production, but also drilling will be completed to add additional (indiscernible) locations. Our guidance for the Raton Basin for December 31, 2003, remains unchanged at 1.375-1.425 Tcf, and our guidance for the Carbon Energy reserves would be anywhere from a 50-100 Bcf, depending on the potential sale of the US assets.

Mark, I will turn the conference call over to you.

We are pleased that we are right on plan, and that we have the capital resources to pursue our existing project in the Raton Basin. The more wells we drill, the more we find there, and the more we expect to trial. It has been a great play for us. It is a long way from being over. We still have probably 700-1000 wells left to drill in the Basin, and we are very pleased about that.

In the meantime, we are looking to enhance our new projects in Alaska, Canada and Kansas. In particular, we are looking at projects and companies and deals in each of those areas. The Pioneer Unit area has now been expanded through additional farmouts and acreage acquisitions, from 70,000 acres to over 127,000 acres that we now have under our control in and around the Pioneer Unit area. Our new 4 well pilot project that we will be drilling later this year will be designed to test the areas outside the Pioneer Unit, and to expand the unit.

In addition, we are currently working on trying to acquire an additional at least 100,000 acres in addition to the acreage that we already have under our control, bringing the total to well over 200,000 acres under our control in the area, which is about the right number, we think, for our coal bed mapping program. And if the play works out, we will be looking to acquire even more acreage in that area.

We are in the process of completing another transaction in the Forest City Basin. The parties have agreed but the leases have not yet transferred. That will bring our acreage position to over 500,000 acres, but we are not stopping there, and we are looking at acquiring at least another 100,000 acres, but probably a couple of hundred thousand acres between now and the end of the year to infill what we have and enhance the acreage in the areas that we think looks the most interesting.

In Canada, we are looking at a large number of deals in that area to try to enhance carbon zone acreage position in that area. We think that coal bed methane acreage in Canada will become very attractive in the future. Like all coal bed methane plays, the Canadian CBM is experiencing a lot of mixed results. We would like to get in there early enough to be a player in what we hope will be an expanding coal bed methane play in southern Alberta.

So we are right on plan, right on target, and we are very excited about the projects that we have, and transferring the technology and the operating expertise we have in the Raton Basin to these other areas. As Kevin indicated, (indiscernible) a stock split was approved by the Board. We think that will do some nice things for our shareholders for liquidity. We felt it was the right thing to do for the Company at this time, and we expect to continue to grow and we expect to continue this very predictable growth profile.

With that, Jeff, we are going to open this up for questions. Go ahead.

(CALLER INSTRUCTIONS). David Tameron from Stifle Nicolaus.

Congratulations on a good quarter. The Forest City Basin -- can you give us a little more color on what you are seeing there, as -- I know you are going to drill, you mentioned in the press release, 40 wells during the fourth quarter. But I wanted to see what your initial impression of the acreage has been there? Let's start there.

Obviously, we are optimistic about it because we are aggressively expanding the acreage we have there already, and we are increasing the number of wells we expect to drill. The data that we have seen at the moment is encouraging, but it has been provided by others based on their operations, their drilling, their activities. So like all CBM plays, it is going to require Evergreen's specific combination of drilling completion and operating techniques before we have a really good sense of what it is going to mean for us. But our expectations have been put out there before that if the play works, we are looking at 0.25 Bcf to 0.4 Bcf per well on average, and then it will simply be a question -- can we control the well costs and keep the well costs below $100,000 a well? If we do, we will have very attractive economics.

I think we have said this before, and -- we have seen nothing to indicate that we should not be able to do this. We are still in the process of constructing equipment, drilling and completion equipment that are being purpose-built for this play. And we are very excited about getting in there, drilling some wells and completing it, and getting our own sense of what is going on. With that much acreage, we are going to have to do several pilot projects in several areas to have a real sense of what we are looking at. But all of the indicators are positive, except let's not kid ourselves -- Evergreen has yet to drill a well there. So we will know more when we do, and that is the purpose of getting even more aggressive and going from 25 wells to 40 wells in the fourth quarter of this year.

Would you care to comment anymore about lease that jumped up during the quarter? I know you mentioned in the -- you had a few comments about it. Was it just simply --

Part of it is a timing issue, and when we first put wells on and put them on pump, that initial investment is capitalized. Those wells have the normal -- equipment has the normal cycle. Our average pump lasts about three years before it needs to be changed. Interestingly enough, the average well on a production-weighted basis has been online about three years. That's all.

Did that catch you a little bit off guard, just comparing it to the guidance you gave in the first quarter?

Clearly, we were -- based on our earlier guidance, we thought we would be able to -- not that we would not incur these costs, but that we would incur them with a different timing. And this may simply be a timing-related issue, but we are very sensitive to this. The other thing is we have noticed that we can control costs and sacrifice production, and we are really working on that balance. We could have brought costs down, but not grown production quite as much. So we are getting some cost creep of pennies an Mcf on our LOEs, but to continue a very current aggressive production growth profile. We still need to look at it. We have a maturing field. We have decided to increase our guidance until we made sure this is -- until we ask ourselves, us this simply a timing problem on costs, or are we really going to be spending 50 cents an Mcf going forward in LOEs? The answer is we were caught a little off guard in relation to the timing, but not in relation to the expenditures, on an absolute basis.

Any update on the progress of the? Has that been pretty much --

The progress has been curtailed for the time being, because we are getting good information on the deeper Raton as we drill deeper disposal wells. A recap -- about 20 percent of our produced water is reinjected into deeper formations. About 40 percent is contained right at the surface and allowed to percolate back in, and about 40 percent of the water is released to ranchers, landowners and people who have water rights in the area. Under permit it's controlled and governed by the Colorado Department of Health. So we continue to drill deeper wells in the Basin. There clearly is deeper potential, but we have noticed, if we bring the deeper wells on quickly, they are higher pressure wells, and there is some adverse impacts to the gathering system that we have discussed in the past. We have so many coal bed methane wells and other wells and drilling the conglomerates and the sands in and around the coals in the Raton and the (indiscernible) formation. So we have so many hundreds of locations left that we simply decided to focus on that for the time being.

John Wolff of Wachovia.

Could you give a little more color on the potential to sell the US Rockies assets, the Carbon assets? Were you approached? And a little bit of the reserve characteristics relative to the entire Carbon deal?

When we announced the Carbon deal, we have had and may still have every intention of developing those assets ourselves. We were looking forward to having another operation in and near Colorado. We hadn't gotten as aggressive in the Forest City Basin at that point, and it looked to us like the Piceance Basin was a natural place for us to be. It may still be a natural place for us to be, but since we announced the transaction, we were approached by others. It's a hot area, it's very competitive, and we were simply -- simply because we were entertaining the conversations, given the full disclosure issues that we are now under, we simply had to acknowledge that we were at least having the conversations. Whether they are completed or not remains to be seen. We may decide that we don't like the price and go ahead and develop it ourselves, or develop it and then find ourselves in a similar situation in a year or two, having other conversations with other active players in the area. There's some very good companies, some good quality companies that are active in the Piceance Basin, the Uintah Basins and the Douglas Creek Arch area; we were hoping to be one of them. We may still be, but we have to acknowledge that we are at least having the conversations. We did not initiate the conversations, however, others who are active in the area or who want to be initiated the conversations with us.

And it's fair to say that you would be looking for a price north of what you're paying for Carbon, in terms of implied unit value?

I will go back to what answer keeps us out of jail. You will be one of the earliest to know about it, you and 10,000 of our other friends in the press release, if we complete a transaction. But obviously, to us it was -- look we're taking on Alaska, we're taking on Canada, we're taking on Kansas, and we still have so much left to do in the Raton Basin. And we simply stopped and asked ourselves, are we biting off more than we can chew? If someone is willing to come up with an attractive price on these assets, are we not as a company better off monetizing these assets and putting the money into future development in the Raton Basin and these other projects? And the answer appears to be, probably. It's simply going to depend on a question of the price, and we have not -- we're not having a formal auction of these properties, we're simply talking for those parties that have indicated an interest, and they decided to talk to us. We have a corporate obligation, as you know, to review all potentially-attractive deals and offers. That would include any deal or offer for any of our properties or assets. The reason we happen to mention this is we are in the middle of an S-4, and under full disclosure requirements we have to talk about the fact that we are at least having the conversations. So it's premature to say what the number will be or if the transaction is going to be completed at all. We simply have to disclose that we are having conversations with potentially-interested buyers. And I can tell there are a number of very interested buyers.

But the real rationale for Carbon was more Canada anyway, right?

When you go back and look at the information we talked about, we were looking forward to two new core areas in western Colorado and eastern Utah, plus Canada. But we have always emphasized that we saw Carbon as the entree we were looking for to Canada and something we could build on. It would be highly likely that if we did complete a sale, we would turn around and put that into further developments and further acquisitions in Canada.

Wayne Andrews of Raymond James.

Related to Alaska, it looks like you are increasing acreage position there before you really have some results. My guess is that you are seeing at least an impressive there. Can you elaborate at all on what you are seen in Alaska?

We drilled 8 wells, as we have discussed, and we fracked 5 of those wells. And we did not frack all of the well column, we fracked the lowest coals. What we want to do is drill north of the Casa Mountain fault. That's a 3000 foot fault, it has 3000 feet of and is very close to the northern edge of the Pioneer Unit. We stopped drilling at 3750 feet, simply because that was the limits of the rig that we sent up there. We were still in the coal packages. What we are looking forward to is getting on the other side of the Casa Mountain fault and seeing what those deeper coals look like, 3000 feet more shallow them they are in the areas we have drilled. So we are very interested in those deeper coals at shallower depths, and we are also doing permeability tests on the deepest coals in the wells we've drilled. But we are also moving up holes to test other coal packages -- quite honestly, thicker coal packages -- the most efficient way to test these wells is to do it with the deepest coals first. We're taking our time and making we really understand this, because this is more of a coal bed methane play, whereas in Kansas we're signaling -- look, we're getting out, we're drilling wells, we're making this happen. Because we see this as a more statistical type gas, conventional gas/shale/coal/sand play, that we need to get out and drill a lot of wells. And we know the gas is there in Kansas, we just need to make sure we can do it at efficient cost.

In Alaska, in contrast, we don't have the shales and the sands that are supporting the play, and we have to make sure we really do the coals right. And as we have discovered with just about every CBM play, pay attention to details and don't rush it. So we are going forward in Alaska. We are excited about it, but -- one of the other reasons why we are interested getting north of the fault is, when we ran into -- when we drilled these 8 wells, we had problems in the drilling on one of the pilots because of the very thick surface gravels, caused by the glaciation in the area. And it took us a lot to get through that. So there are some very interesting aspects of the play. We want to test the shallower coals in the wells that we have now, and we want to test the deeper goals and the coals below the deepest coals we could drill north of the fault. And we also know that north of the fault we are going to have thinner surface gravels, and it will cost us less to drill.

So it may be that -- when we went into this play in the first place, we were always very interested in the coal packages in the Matanusca and Sisidna Valley areas, and the reason we did the Pioneer Unit when we did is it's simply because it became available. But that was not our initial incentive to look at this area. Our initial incentive was looking at the area right around the Pioneer Unit, but when the opportunity came up, we felt we couldn't pass it up, so we acquired it for fairly little money -- a nice unitized area that has not just CBM potential, but even deeper potential right in the Pioneer Unit. The shallow gas potential, however, above the -- outside the unit -- this next group of wells we are going to drill would have been the first group of wells we would have drilled in a perfect world, if we had simply been able to get all of the acreage at the same time. It simply did not come to us that way.

So we are interested in testing the coals that we have opened now in the existing five wells. We are interested in testing the shallower coals in those wells. We are extremely interested in testing the deeper coals where they're more shallow. We feel that we may get into some situation where there is even overpressuring in the coals, and some of the best coal bed methane wells in the San Juan basin, of course, are drilled in the areas where the hydrostatic pressure gradage is overpressured. So it's encouraging, but too early to claim success. We want to make sure we have the right acreage position in the right areas to really get after this the right way, and that's what we are doing.

Barry Sahgal of Brean Murray.

I wanted to get a quick one minute primer on the Forest City Basin, just to give us some background. Maybe you have done this before and I haven't been paying attention. But now that you are building some project momentum over there, perhaps you could just share with us who some of the industry players are, some of the unit well expectations on a line item basis, and just some kind of some kind of view as to how this thing all fits together?

We have discussed this in the past, and I will try to recite the highlights of some of that. The Forest City Basin in eastern Kansas has been thought of as the poor man's oil play for years. It's really kind of a misnomer. I think it is the poor man's gas play. lots of coal, lots of shale and lots of tight sands. And a typical stratigraphic down to 3000 feet would have half a dozen to a dozen thin coals. It would have half a dozen fractured shales. It would have several tight gas and lenticular packages in and out. There are a number of players who have gone into the area, mostly to the South. The Forest City Basin and the Cherokee Basin are separated by arch, and they are very similar, with the exception of this large arch kind of in the middle. And players that have been active in the area included Debon) Anadarko, Burlington, JM Hubert Corp. These are all companies that have drilled wells and experimented in the area, but not really in the area that we are planning to focus on. They have tended to be South. So there are a lot of companies that have decided that this area has interest. We think it does, too.

We think -- in this area, when we look at the coals, the shale and the sand packages that are there, we know there's plenty of gas there. And of course that is a relative term. There is plenty of gas in a Powder River Basin coal bed methane play -- although there are by no means the characteristics that we see in the Powder River Basin, although we do expect to get comparable results in terms of 0.25-0.4 Bcf per well, as opposed to more than a Bcf a well that we see in the Raton Basin or that players have seen in the San Juan Basin. So this is, again, a different kind of coal bed methane play, which we think we will be enhanced by fractured shales and tight sands interbedded with the coals -- all, we hope, highly gas charged.

To us, it is a natural for us, because it allows us to do what we do well -- vertically integrate it, control the process, keep the costs down and have enough acreage position to get the economies of scale. These are all -- and it's in an area where we can get things done, with a good gas market and a friendly regulatory environment, and virtually all 100 percent fee acreage. So no issues that other producers are seeing in the Rockies being held up with their drilling plans, waiting for an environmental impact statement or environmental assessment, or simply people who don't want them there. Typically, the people who own the surface due own the mineral rights. They are farmers, and they would like nothing more than to see a producing well on their property, and enhance their farm income. A very friendly place for the natural gas business, a very friendly regulatory environment with an area where we could acquire a very large acreage position and take advantage of our core skills.

One of the things to keep in mind is these are older coals. Typically in the Rockies you'll see cretaceous-age coals; these will be more Pennsylvanian-aged coals. And they may have permeable -- the reason we have taken such a large acreage position is we are expecting variable permeability across these acreage blocks, and although we are going to be drilling quite a few different pilot projects, we expect to get very different results in each pilot, but get all of the indicators we need to know where to start the play, where to look and where to be aggressive. After drilling 40 wells in this basin, I will give you a hint -- if we say we are going to drill 50 wells next year, that means we have not figured it out; if we say we are going to drill more than 200 wells next year, that means we are very excited about what we are seeing. And at the moment, we expect to drill at least 200 wells next year.

Your completed well costs, I think you had mentioned, were going to be about 100,000 a well?

We think so.

How much more will we need to add on for infrastructure?

There is a wonderful pipeline system in the area already, and what we are asking ourselves is -- should we do the gathering ourselves, as we have in the Raton basin, or do it in a partnership? But probably, the upper end of cost would be on a prorated basis -- about 75,000 per well.

Adrian Daas of Hartwell.

I am curious -- you have just given us a wonderful tutorial on the Kansas City acreage. Could you give us a similar tutorial, please, on the expectations and the attention you are going to pay to the acreage you've been acquiring near your Raton Basin? Which, I know -- I guess -- and though you have not mentioned it very much -- that you have continued to acquire acreage there? You have got these existing wells that are down. Could you bring us up to speed on what the plans are, both short-term and long-term, for this acreage acquisition, as well as production?

We have not been talking much about it because we are looking to see if this is a scenario that we want to unitize and try to put a federal unit together on, and go for the deeper formations below the coal -- the Pierre, the Nibrerra, and the interbedded formations there in those -- in the various members, down to the Dakota. The answer is we haven't put a unit together on that area, and we are trying to decide do we want to or not and what is the best way to explore this while we still have hundreds of wells left to drill in the coal groups. So we haven't really -- we have been going slow in that area because it is a different kind of play. I haven't really give you much information, because --

-- future thinking on this, or how long it will it take you to make these decisions? Or is it just a question of these other areas being much more attractive? Where are you ranking this particular project, and can you give us an idea of the acreage you now control there?

If we didn't have the Forest City Basin, we would be more aggressive about drilling the fractured Pierre shales, probably with highly-deviated wells. And we think the key to this play -- and we haven't really been talking about it, because we have not yet acquired much expertise in directional drilling; but we expect to, and we expect to start drilling more directional wells in and around the Raton Basin, to test some of these plays -- we think that the best way to go after these fractured shales is with horizontal or highly-deviated wells. And we simply have not gotten around to drilling those yet with everything else that we are doing. That is why we have not really released information. But we think that will be one of the keys to success in this kind of clay -- versus massive hydraulic fracks in the area, we think that this is an area that will lend itself to directional drilling.

Ellen Hannan of Bear Stearns.

On the Carbon acquisition, what they're doing in Canada. Do they have any coal bed methane production now, or is it all from conventional sands?

They have no coal bed methane production. any coal bed methane reserves, although we did see coal bed methane potential that we were interested in testing. That's one of the reasons why we were and are interested in the Carbon acreage, in that both in the complex, as well as the Canadian properties, they booked absolutely no coal bed methane reserves or potential. And we see that we are basically getting -- we're able to acquire carbon at a good price and get a free look, prospectively -- or a free call on their CBM rights, and our ability to possibly develop those. So we are very interested in it, but no reserves have yet been booked by either Carbon or Evergreen on any of these properties.

Is there anything left to be written off in the international arena?

There's no amounts left on our books. Any costs we incur will be an expense, currently.

I will also comment that -- Bill Miller had asked a question about -- where the answer turned out to be horizontal wells. We have not really said much about this in the markets, but it is something that we do plan on drilling. We are going to start drilling horizontal wells in some of the fixed (indiscernible) coals in the Raton Basin area, where we think the permeability from the cores is great and we see very good shells while drilling. And we are going to test this, and we are going to test this in some of the coals and we're going to test it in some of the deeper shales. You are going to see us continue to experiment; that's what we do. We say all along that we like to try things, we like to be on the leading edge of technologies, we like to be looking to apply new technologies to existing areas and new areas. This is just part of it. So you are going to hear more from us in the future about horizontal drilling into some of the coals and shales and fractured formations, but we just haven't done it yet. And that's why we haven't really been talking about it. But hopefully we will be talking about it at the end of this year.

Brian Singer of Goldman Sachs.

On Canada, are there specific opportunities to expand your acreage now, given the earlier comments you made about redeploying the capital potential sale of Carbon's US properties? Or is this something longer-term?

There are immediate opportunities to do joint ventures with existing companies, to acquire some acreage in the area. Most of the opportunities would be asset sales of existing properties, where you are getting additional rights that would be of interest to us, or company acquisitions. There are hundreds of Canadian companies that people are doing -- you're starting to see more and more a lot of US companies going across the border to joint venture or acquire companies in Canada with an eye toward this. We are simply doing it also, and we see opportunities to acquire acreage, to acquire assets, to acquire companies. And we are reviewing all of those.

Would you expect that to happen within the short-term if you were to sell the US properties, or is there a relation --

There might be a relationship. Again, it is just a timing question, so I am not really sure how to answer the question.

Thomas Connolly with 10 Square Research.

I have 2 financial questions for Kevin. On the report that was issued this morning, there is a mention of a hedging loss of 2.9 million for the three months ended June 30. And I was looking on the P&L statement, and I could not find it there. Where would I find it?

That hedging loss is just netted in gas prices. It is just the difference between the market value of the hedges and the hedge itself that we had entered into. So it's just part of the gas price.

So it would be in natural gas revenues?

That's right 53 million.

The second question that I have is -- on the balance sheet, there is an item under current liabilities for about $15.5 million in derivative instruments. Could you give us a little bit of a feel for that?

Under FAS 133 accounting for derivatives, we are required to mark to market our derivative position through whatever period we have entered into those financial hedges. So in our case, all of the hedges that we have entered into for 2003, and also for some of those for 2004, we have to book an adjustment for the fair market value of those hedges. So in this case, our hedges were a little bit underwater, so we had to increase our liabilities by 15.5 million. And the offset to that is in accumulated other comprehensive loss. So it's no P&L affect at this point in time -- we just have to give effect to the future value of those hedges.

Kevin, could I ask you to back up just a sentence or 2 there? I don't think I understood the last 2 sentences.

Generally, because these hedges have a future value based on Black Scholls models and so forth, if the hedge is not -- is less than the fair market value right now of the commodity, if we have a hedge at 4.37 and the fair market value is at $5, we have to report a liability for that difference. That means that in the future we won't receive that much additional revenue. However, there is no P&L effect for that because of how we are able to account for that under FAS 133. Because of our hedge accounting, we are able to record those adjustments as we incur those sales volumes.

It passes through the P&L statement -- similar to what we just talked about a moment ago -- in the natural gas revenues?

Right. Only when we have the sale of that commodity.

And as you mentioned in this morning's report, you had a hedging loss of almost 3 million in the three months ended June 30. I am not sure I understand why it all washes out. If the derivatives are -- require a $14 million addition in the first 6 months, where do they wash out?

The offset is a liability, and the other debit, so to speak, is in equity. So as we -- for the third quarter, that 15.5 million will be adjusted. If gas prices continue to drop and our hedges are in excess of those gas prices, we would not have any liability; it would reduce the amount of loss we would have.

But if you close the books today, you would have -- do I understand that if you close the books tomorrow, you would have to write off a significant amount of money in those derivatives?

I don't think so, because this is based on a future value, and I don't know what gas prices are going to do.

Okay. Because of the future value?

Right.

So there is a potential there over the life of the derivative that there might be plus or minus arithmetic entering into the revenue stream?

That's correct.

You must have had a lot of fun talking to the accountants on this one, at least the first time around.

Chris Pikul of AG Edwards.

It's Greg McMichael. Kevin, would you review the Carbon guidance again with us? I recognize that we are not sure on the closing there, but in terms of the production guidance that you gave earlier?

Assuming that we would close on Carbon at September 30, we think that the fourth quarter production for Carbon would be as follows -- the US assets could be anywhere from 0.7-0.8 Bcf for the fourth quarter, and the Canadian assets would be 1.1-1.2 for the fourth quarter.

That's not assuming any drilling on those assets at this point, from Evergreen?

Not evergreen, but Carbon is continuing to develop those assets. They are drilling, they are completing wells and they are enhancing our production profile. So they are moving forward on their program this year.

As far as your review with the SEC, is it a reasonable expectation that we would be closed on the beginning of the fourth quarter?

That is our goal. We are in the registration process right now. What takes a lot of time is the fact that once the S-4 goes effective, we need to provide -- or Carbon needs to provide their shareholders 20 business days with which to vote on the transaction and hold a shareholder meeting. That would be -- based on our timing right now, that would be scheduled roughly around September 29, and we think that we could close the transaction on September 30.

Ironically, though, over 70 percent of the Carbon shareholders have already approved the deal.

Kevin, on operating cash flow before changes in current assets and current liabilities for the quarter, was that $1.82? Is that 36.3 million?

Generally, I can't comment on that anymore because of Regulation G, but I think your calculation is correct. That is a true statement, in that as of this year because of Regulation G, we are no longer able to provide non-GAAP financial information, which would include a cash flow calculation. So I think generally, everybody has that concept down of how we account for that. So I think you have it right.

So just by removing changes in operating assets and liabilities, we get to the number?

That's correct.

Warren Clifford of Clifford Capital Management.

What is the hedge position for 2004 now?

Our hedge position for 2004 is about 30 million a day. We have got the (indiscernible) at 20 million a day, with a floor of 3.30 and a ceiling of $5.05, and we have a swap in place for 10 million a day at a net price of 3.86.

Adrian Daas of Hartwell.

You have obviously written off the international assets to zero. I take it that is coincident with a lack of interest among potential buyers for those assets?

We are still talking to other buyers. Some of those buyers are having their own financial problems. Quite honestly, we wrote off the assets so we would not have to answer any more questions about it.

There was a small gain on sale of investments in the quarter. What did that relate to?

We had entered into a transaction with another company a couple or three years ago, and as a result of that, we acquired stock in that company. It was a small public company. We had about 680,000 shares, with a cost basis of about $2. Their stock was up nicely over that period of time at 4-plus. We felt it was time just to monetize that investment and start selling off that stock, so we sold not quite all of it as of the end of June, and then we sold the remaining amount in early July. We had about a $950,000 gain as of June 30, and about a $350,000 gain as of the first part of July. So we no longer have that investment.

At this time, there are no further questions.

Jeff, thank you. I will mention one thing. reminded that even though we have been a little frustrated we have not been able to close the Carbon deal a little more quickly by going through the process, Carbon is still methodically pursuing their own business plan, increasing acreage and drilling wells and looking to increase production in the US and in Canada. In particular, Carbon Energy Canada is methodically acquiring additional acreage at crown shales. They are doing their own unsolicited offers to working interest owners in key areas. It' just that we are trying to be coordinated on those efforts. They are still pursuing their business plan, it's just that we have not been able to get quite as aggressive in this area as we would like, pending the final merger.

I would like to thank everyone for participating in our second-quarter conference call. I'll turn it back over to John Kelso.

Again, if anyone has additional questions, please feel free to call. And we hope to see several of you next week at the conference. That concludes our second-quarter conference call.

Thank you for joining today's conference call. You may now disconnect.

(CONFERENCE CALL CONCLUDED)